Fracturing method using a low-viscosity fluid with low proppant settling rate

ABSTRACT

A fluid design with enhanced proppant-carrying capacity utilizes a low-viscosity fluid with high proppant carrying capacity and low required power for injection into a hydrocarbon-bearing, subterranean formation. A preferred viscosifying agent that comprises a copolymer polymerized from an acrylic acid monomer and a monomer selected from: a) at least one carboxylic acid monomer; b) at least one C1 to C5 alkyl ester and/or at least one C1 to C5 hydroxyalkyl ester of acrylic acid or methacrylic acid; c) one crosslinking monomer; and optionally d) at least one α,β-ethylenically unsaturated monomer, may be used to produce a fracturing fluid that has the pumpability of a slick water fluid and the proppant-carrying ability of a cross-linked gel. An optimization process to optimize hydraulic fracture design evaluates and quantifies the proppant-carrying capacity of the invented fluid and its impact in the proppant transport during fracturing.

CROSS-REFERENCE TO RELATED APPLICATIONS

none

FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable

BACKGROUND OF THE INVENTION 1. Field of the Invention

The present invention generally relates to methods and compositions forhydraulically fracturing subterranean formations. More particularly, itrelates to a system for Fracturing that uses fluids capable ofsuspending proppant materials without requiring high pumping power.

2. Description of the Related Art Including Information Disclosed Under37 CFR 1.97 and 1.98 Fracturing Fluids and Additives

Fracturing fluids are pumped into the well to create conductivefractures and bypass near-wellbore damage in hydrocarbon-bearing zones.The net result is an expansion in the productive surface-area of thereservoir, compared to the un-fractured formation. A series of chemicaladditives are selected to impart a predictable set of properties of thefluid, including viscosity, friction, formation-compatibility, andfluid-loss control.

To create the fracture, a fluid is pumped into the wellbore at a highrate to increase the pressure in the wellbore at the perforations to avalue greater than the breakdown pressure of the formation. Thebreakdown pressure is generally believed to be the sum of the in-situstress and the tensile strength of the rock. Once the formation isbroken down and the fracture created, the fracture can be extended at apressure called the fracture-propagation pressure. Thefracture-propagation pressure is equal to the sum of:

The in-situ stress

The net pressure drop

The near-wellbore pressure drop

The net pressure drop is equal to the pressure drop down the fracture asthe result of viscous fluid flow in the fracture, plus any pressureincrease caused by tip effects. The near-wellbore pressure drop can be acombination of the pressure drop of the viscous fluid flowing throughthe perforations and/or the pressure drop resulting from tortuositybetween the wellbore and the propagating fracture. Thus, thefracturing-fluid properties are very important in the creation andpropagation of the fracture.

The ideal fracturing fluid should:

-   -   Be able to transport the propping agent in the fracture    -   Be compatible with the formation rock and fluid    -   Generate enough pressure drop along the fracture to create a        wide fracture    -   Minimize frictional pressure losses during injection    -   Be formulated using chemical additives that are approved by the        local environmental regulations.    -   Exhibit controlled-break to a low-viscosity fluid for cleanup        after the treatment    -   Be cost-effective.

The viscosity of the fracturing fluid is an important point ofdifferentiation in both the execution and in the expected fracturegeometry. Many current practices, generally referred to as “slick water”treatments, use low-viscosity fluids pumped at high rates to generateelongated, well contained or complex fractures with low-concentrationsof propping agent (0.2-5 lbm proppant added (PPA) per gallon). In orderto minimize risk of early settling, pumping rates must be sufficientlyhigh to transport proppant over long distances (often along horizontalwellbores) before entering the fracture. By comparison, for conventionalwide-biwing fractures the carrier fluid must be sufficiently viscous(normally 50 to 1000 cp at nominal shear rates from 40-100 sec⁻¹) totransport higher proppant concentrations (1-10 PPA per gallon). Thesetreatments are often pumped at lower pump rates and may create widerfractures (normally 0.2 to 1.0 in.) with abnormal height growth andcontainment.

The density of the carrier-fluid is also important. The fluid densityaffects the surface injection pressure and the ability of the fluid toflow back after the treatment. Water-based fluids generally havedensities near 8.4 ppg. Oil-base fluid densities will be 70 to 80% ofthe densities of water-based fluids. Foam-fluid densities can besubstantially less than those of water-based fluids. In low-pressurereservoirs, low-density fluids, like foam, can be used to assist in thefluid cleanup. Conversely, in certain deep reservoirs (includingoffshore frac-pack applications), there is a need for higher densityfracturing fluids whose densities can span up to >12 ppg.

A fundamental principle used in all fracture models is that “thefracture volume is equal to the total volume of fluid injected minus thevolume of fluid that leaks off into the reservoir.” The fluid efficiencyis the percentage of fluid that is still in the fracture at any point intime, when compared with the total volume injected at the same point intime. The concept of fluid loss has been used to determine fracturearea. If too much fluid leaks off, the fluid has a low efficiency (10 to20%) and the created fracture volume will be only a small fraction ofthe total volume injected. However, if the fluid efficiency is too high(80 to 90%), the fracture will not close rapidly after the treatment andcannot keep the proppant in place. Ideally, a fluid efficiency of 40 to60% will provide an optimum balance between creating the fracture andhaving the fracture close down after the treatment to hold proppant inplace.

In most low-permeability reservoirs, fracture-fluid loss and efficiencyare controlled by the formation permeability. In high-permeabilityformations, a fluid-loss additive is often added to the fracture fluidto reduce leakoff and improve fluid efficiency. In naturally fracturedor highly cleated formations, the leakoff can be extremely high, withefficiencies down in the range of 10 to 20%, or less. To fracturenaturally fractured formations, the treatment often must be pumped athigh injection rates with fluid-loss additives to stimulate a fracturenetwork.

Categories of Fracturing Fluids

The categories of fracturing fluids currently available consist of:

Viscosified water-based fluids

Nonviscosified water-based fluids

Gelled oil-based fluids

Acid-based fluids

Foam fluids

Water-Based Fracturing Fluids—Uncrosslinked Polymers and “Slick Water”

A common practice in the hydraulic fracturing of gas-producingreservoirs is the use of non-viscous “slick water” fluids pumped at highrates (>60 bpm) to generate narrow fractures with low concentrations ofproppant. In recent years, these treatments have become a standardtechnique in fracture stimulation of several U.S. shales, including theBarnett, Marcellus, and Haynesville and yield economically viableproduction. The low proppant concentration, high fluid-efficiency, andhigh pump rates in slick water treatments yield highly complexfractures. Additionally, compared to a traditional bi-wing fracture,slick water fractures often find the primary fracture connected tomultiple sets (usually 2-3 sets) of natural fractures, which were formedin different geological environments and present various propertiesincluding orientation, frictional resistance, density and size. Coupledwith multistage fracture completions and multiple wells collocated on apad, complex fracture networks yield a high degree of reservoir contactarea.

The most critical chemical additive for slick water-fracture executionis the friction reducer (FR). The high pump rates for slick watertreatments (often 60-100 bbl/minute) necessitate the action of FRadditives to reduce friction pressure up to 70%. This effect helps tomoderate the pumping pressure to a manageable level during proppantinjection. Common chemistries for friction reduction includepolyacrylamide derivatives and copolymers added to water at lowconcentrations. Additional additives for slick water fluids may includebiocide, surfactant (wettability modification), scale inhibitor, andothers. The performance (friction reduction) of slick water fluids aregenerally less sensitive to mix-water quality, a large advantage overmany conventional gelled fracturing fluids. However in high-salinitymix-water, many FR additives may see a loss in achievable frictionreduction. Other advantages and disadvantages of slick water fluids andexecution (compared to that of gelled fracturing fluids) are detailedbelow:

Advantages:

-   -   High retained conductivity, due to no filtercake present.    -   Reduced sensitivity to salinity and contaminants in mix-water.    -   Reduced number of fluid additives required for slick water        fracturing fluid.

Disadvantages:

-   -   Larger volumes of water often required for fracture design        (compared to “gelleg” fracturing fluids).    -   Larger horsepower requirement (to maintain high pump rates,        60-110 bpm).    -   Limited fracture-width (due to low maximum concentration        proppant in low viscosity).    -   Reduced %-flowback-water recovery (due to imbibition of        fracturing fluid in complex fracture network far from wellbore).    -   Limitation to fine-mesh propping agents (due to reduced ability        of nonviscous fluids in transport of large proppants).

As the anticipated proppant-suspension capacity of slick water fluids isquite low, a complementary solution is the use of linear (uncrosslinked)gels. These fluids, based on uncrosslinked solutions of polysaccharides(i.e., guar, derivatized-guar, HEC, xanthan), have viscosities of up to100 cP at 100 sec⁻¹ at surface temperature, which depend on polymerconcentration. As this viscosity is several orders of magnitude higherthan slick water, linear gels have improved proppant-suspension. Whenuncrosslinked gels are used in late-slurry stages of a fracturingtreatment (where the pad and early-slurry stages used slick water),these are often referred to as “hybrid” fracturing treatments. [Notethat “hybrid” may also refer to fracture treatments usingcrosslinked-gel to follow slick water, crosslinked-gel followinglinear/un-crosslinked, and other variations]

Polymers are used to viscosify the fluid. Crosslinkers are used tochange the viscous fluid to a pseudoplastic fluid. Biocides are used tokill bacteria in the mix water. Buffers are used to control the pH ofthe fracture fluid. Surfactants are used to lower the surface tension.Fluid-loss additives are used to minimize fluid leakoff into theformation. Stabilizers are used to keep the fluid viscous at hightemperature. Breakers are used to break the polymers and crosslink sitesat low temperature.

Slick water or slick water fracturing is a method or system ofhydro-fracturing that involves adding chemicals to water to increase thefluid flow. It is a fracture method that relies on high volumes of waterand minimal chemical additives. Fluid can be pumped down the wellbore asfast as 100 bbl/min. to fracture the shale. Without using slick water,the top speed of pumping is around 60 bbl/min. Slick water fracturingmethods were used before gels and high viscosity fluids became theindustry standard for most fracturing designs, but the simple design ofa slick water fracturing has proven to produce a more complex fracturenetwork in certain formations—e.g. the middle Bakken formation.

The process involves injecting friction reducers, usually apolyacrylamide. Biocides, surfactants and scale inhibitors can also bein the fluid. Friction reducers speed the mixture. Biocides such asbromine prevent organisms from clogging the fissures and creating slimedownhole. Surfactants keep the sand suspended. Methanol and naphthalenecan be used for biocides. Hydrochloric acid and ethylene glycol may beutilized as scale inhibitors. Butanol and ethylene glycol monobutylether (2-BE) are used in surfactants. Slick water typically uses morewater than earlier fracturing methods—between one and five milliongallons per fracturing operation.

Other chemical compounds sometimes used include benzene, chromium and ahost of others. Many of these are known to be toxic and have raisedwidespread concern about potential water contamination. This isespecially true when the wells undergoing slick water hydro-fracturingare located near aquifers that are being used for local drinking water.Hydro-fracturing activity is heavily regulated by state agencies.

In summary, slick water is a water-based fluid and proppant combinationthat has low-viscosity. It is typically used in highly-pressurized,deeper shales, while fracturing fluids using nitrogen foam are morecommon in shallow shales and those that have lower reservoir pressure.

There are primarily three types of fracturing fluids currently used.These are water frac or slick water, linear gel, and crosslinked gel.All three of these frac fluids have different properties andapplications.

Water frac is water containing a friction reducer and possibly abiocide, surfactant, breaker or clay control additive. This fluid has alow viscosity of 2-3 cP, which requires a high pump rate to transportproppant. Small proppant size like 40/70 is common with this fluid dueto its low viscosity. Water frac is the least damaging to the proppantpack of the three frac fluid types and it is commonly used in gas wells.

Linear gel is water containing a gelling agent like guar, HPG, CMHPG, orxanthan. Other possible additives are buffers, biocide, surfactant,breaker, and clay control. This fluid has a medium viscosity of 10-30cP, which results in improved proppant transport and wider frac comparedto water frac fluid. Medium proppant size like 30/50 is common with thisfluid. Linear gel is more damaging to the proppant pack than water fracand it is commonly used in both gas and oil wells.

Cross-linked gel is water containing any of the gelling agents used inlinear gel and a crosslinker like boron (B), zirconium (Zr), titanium(Ti) or aluminum (Al). Other possible additives are buffers, biocide,surfactant, breaker, and clay control. This fluid has a high viscosityof 100-2500 cP at 100⁻¹ R1:B5 bob configuration, which results in betterproppant transport and wider fracs compared to linear gel fracturingfluid. Large proppant sizes like 20/40 and 16/30 are common with thisfluid especially at low pump rates such as <60 BPM. Cross-linked gel ismore damaging to the proppant pack than linear gel and it is commonlyused in oil and high liquid wells because of its common residual of7-12%.

Other less common fracturing fluids include gelled oil, gelled acid,foamed oil with nitrogen, foamed water with nitrogen or carbon dioxide,and gelled LPG.

Polyacrylamide is a friction reducer used to “slick” the water tominimize friction and lower the power required to pump the fracturingfluid. Petroleum distillates and hydro-treated light petroleumdistillate are used as carrier fluids for the polyacrylamide frictionreducer. Methanol and ethylene glycol are used as product stabilizers orwinterizing agents.

Guar gum and a polysaccharide blend are gelling agents used to thickenthe water in order to suspend the sand (proppant). Petroleum distillatesand hydro-treated light petroleum distillate are used as carrier fluidsfor guar gum in liquid gels.

Given today's technology, chemicals must be used in hydraulic fracturingto ensure the producing formation is effectively treated. Generalhydraulic fracturing chemical usage including the types of chemicals,their uses in the process and the result of their use are discussedbelow.

Guar gum is a galactomannan—a polysaccharide consisting of a mannosebackbone with galactose side groups. It is primarily the groundendosperm of guar beans and is typically produced as a free-flowing,off-white powder. It is known that guar can stiffen water to the extentthat a mixture is able to carry sand into horizontal sections of wellsand permit fracturing operations therein.

Guar gum shows a clear, low-shear plateau on the flow curve and isstrongly shear thinning. The rheology of guar gum is typical for arandom coil polymer. It does not show the very high low-shear plateauviscosities seen with more rigid polymer chains such as xanthan gum. Itis very thixotropic above 1% concentration, but below 0.3%, thethixotropy is slight. Guar gum shows viscosity synergy with xanthan gum.Guar gum and micellar casein mixtures can be slightly thixotropic if abi-phase system forms.

Guar gum is economical because it has almost eight times thewater-thickening potency of cornstarch and only a small quantity isneeded for producing sufficient viscosity. Thus, it can be used invarious multiphase formulations: as an emulsifier because it helps toprevent oil droplets from coalescing, and/or as a stabilizer because ithelps to prevent solid particles from settling. Guar gum is aviscosifier with very favorable rheological properties. It has aparticularly useful ability to form breakable gels when cross-linkedwith boron. This makes it extremely valuable for hydraulic fracturing.

Fracturing entails the pumping of sand-laden fluids into an oil ornatural gas reservoir at high pressure and at a high flow rate. Thisproduces cracks in the reservoir rock and then props the cracks open.Water alone is too “thin” to be effective at carrying proppant sand, soguar gum is one of the ingredients often added to thicken the slurrymixture and improve its ability to carry proppant. There are severalproperties which are important: 1. Thixotropic: the fluid should bethixotropic, meaning it should gel within a few hours. 2. Gelling andde-gelling: The desired viscosity changes over the course of a fewhours. When the fracturing slurry is mixed, it needs to be thin enoughto make it easier to pump. Then, as it flows down the pipe, the fluidneeds to gel in order to support the proppant and carry it deep into thefractures. After that process, the gel has to break down so that thefracturing fluid can be recovered by flow back but leave the proppantbehind. This requires a chemical process which produces then breaks thegel cross-linking at a predictable rate.

Guar+boron+proprietary chemicals can accomplish both of these goals atonce.

Manufacturers define different grades and qualities of guar gum by theparticle size, the viscosity generated with a given concentration, andthe rate at which that viscosity develops. Coarse-mesh guar gums willtypically, but not always, develop viscosity more slowly. They mayachieve a reasonably high viscosity, but will take longer to achieve. Onthe other hand, they will disperse better than fine-mesh, all conditionsbeing equal. A finer mesh, such as a 200 mesh, requires more effort todissolve.

Modified forms of guar gum are available commercially, includingenzyme-modified, cationic and hydropropyl guar

Guar Gum and Guar Derivatives in Fracturing

Guar gums are preferred as thickeners for Enhanced Oil Recovery (EOR),guar gum and its derivatives account for most of the gelled fracturingfluids. Guar is more water-soluble than other gums, and it is also abetter emulsifier, because it has more galactose branch points. Guar gumshows high low-shear viscosity, but it is strongly shear-thinning. Beingnon-ionic, it is not affected by ionic strength or pH but will degradeat low pH at moderate temperature (pH 3 at 50° C.). Guar's derivativesdemonstrate stability in high temperature and pH environments. Guar useallows for achieving exceptionally high viscosities, which improves theability of the fracturing liquid to transport proppant. Guar hydratesfairly rapidly in cold water to give highly viscous pseudoplasticsolutions of, generally, greater low-shear viscosity than otherhydrocolloids. The colloidal solids present in guar make fluids moreefficient by creating less filter cake. Proppant pack conductivity ismaintained by utilizing a fluid that has excellent fluid loss control,such as the colloidal solids present in guar gum.

Guar has up to eight times the thickening power of starch.Derivatization of guar gum leads to subtle changes in properties, suchas, decreased hydrogen bonding, increased solubility in water-alcoholmixture, and improved electrolyte compatibility. These changes inproperties result in increased use in different fields, like textileprinting, explosives, and oil-water fracturing applications.

Crosslinking Guar

Guar molecules have a tendency to aggregate during the hydraulicfracturing process, mainly due to intermolecular hydrogen bonding. Theseaggregates are detrimental to oil recovery because they clog thefractures, restricting the flow of oil. Cross-linking guar polymerchains prevents aggregation by forming metal—hydroxyl complexes. Thefirst cross-linked guar gels were developed in the late ‘60's. Severalmetal additives have been used for crosslinking, among them arechromium, aluminum, antimony, zirconium, and boron. Boron, in the formof B(OH)3, reacts with the hydroxyl groups on the polymer in a two-stepprocess to link two polymer strands together to form bis-diol complexes.

A one-to-one 1,2 diol complex and a one-to-one 1,3 diol complex placethe negatively charged borate ion onto the polymer chain as a pendantgroup. Boric acid itself does not apparently complex to the polymer sothat all bound boron is negatively charged. The primary form ofcrosslinking may be due to ionic association between the anionic boratecomplex and adsorbed cations on the second polymer chain. Thedevelopment of cross-linked gels was a major advance in fracturing fluidtechnology. Viscosity is enhanced by tying together the low molecularweight strands, effectively yielding higher molecular weight strands anda rigid structure. Cross-linking agents are added to linearpolysaccharide slurries to provide higher proppant transportperformance, relative to linear gels.

Lower concentrations of guar gelling agents are needed when linear guarchains are cross-linked. It has been determined that reduced guarconcentrations provide better and more complete breaks in a fracture.The breakdown of a cross-linked guar gel after the fracturing processrestores formation permeability and allows increased production flow ofpetroleum products

When fracturing, viscosity plays a major role in providing sufficientfracture width to ensure proppant entrance into the fracture andminimize premature screen-out, carrying the proppant from the wellboreto the hydraulic fracture tip and further diverting the proppant intothe fracture network, generating a desired net pressure to controlhydraulic fracture height growth and natural fracture reactivation, andproviding fluid loss control. The fluid used to generate the desiredviscosity must be safe to handle, environmentally friendly, non-damagingto the fracture conductivity and to the reservoir permeability, easy tomix, inexpensive and able to control fluid loss. This is a verydemanding list of requirements that has been recognized since thebeginning of hydraulic fracturing.

The selection of a proper fracturing fluid begins with choosing the padvolume required to create the desired fracture geometry. This istypically followed by choosing how much viscosity the fluid needs tohave in order to:

Provide sufficient fracture width to insure proppant entrance into thefracture and prevent premature screen-out.

Provide a desired net pressure to either treat some desired hydraulicfracture height growth or prevent breaking out into some undesirablezone for example water and control the extent of reactivated naturalfracture network.

Provide carrying capability to transport proppant from the wellbore tothe hydraulic fracture tip and deliver proppant from hydraulic fractureinto complex natural fracture network.

Control fluid loss. In cases where a gel filter cake cannot form, thefracturing fluid viscosity (i.e. Cl) may be the main mechanism for fluidloss control. This choice system continues when it comes to selectingthe appropriate fluid system for a propped or acid fracturing treatment.The considerations include:

Safe—The fluid should expose the on-site personnel to a minimal danger.

Environmentally Friendly—The composition of the fluid should be as“green” as possible.

Breaker—The fluid must “break” to a low viscosity so that it can flowback and allow cleanup of the fracture.

Cost Effective—The fluid must be economical and not drive the treatmentcost to an unacceptable level.

Compatibility—The fluid must not interact and caused damage with theformation mineralogy and/or formation fluids.

Clean-up—The fluid should not damage the fracture conductive of thefracture or, to prevent water blocks, change the relative permeabilityof the formation. This becomes very important in low pressure wells orwells that produce very dry gas.

Easy to Mix—The fluid system must be easy to mix even under very adverseconditions.

Fluid Loss—The fluid needs to help control fluid loss. An ideal fluidshould have fluid loss flexibility.

In summary, an ideal fracturing fluid would be one that has an easilymeasured controllable viscosity, controllable fluid losscharacteristics, would not damage the fracture or interact with theformation fluid, would be completely harmless and inert and cost lessthan $4.00 per gallon. Unfortunately this is currently not possible, socompromises have to be made.

Of these factors the fluid viscosity is the major fluid-relatedparameter for fracture design and operation. However, how much viscosityis needed is often overestimated. Excessive viscosity increases costs,reduces time-efficiency for injection, raises treating pressure (whichmay cause undesired height growth and send fluid and proppant intonon-productive zones), and can reduce fracture conductivity since manyof the chemicals used to increase viscosity leave residue which damagesthe proppant permeability.

There are several types of fracturing fluids and a wide range of fluidadditives.

The types of fluids include:

Water based fluids

Oil based fluids

Energized fluids

Multi-phase emulsions

Acid Fluids

Additives include:

Gelling agents

Crosslinkers

Breakers

Fluid loss additives

Bactericides

Surfactants and Non-emulsifing agents

Clay control additives.

The purpose and downhole result(s) of common additives for fracturingfluids are discussed more fully, below.

The vast majority of fracturing fluids used today use water as the basefluid. Generally, the components that make up cross-linked fracturingfluids include a polymer, buffer, gel stabilizer or breaker and acrosslinker. Each of these components is critical to the development ofthe desired fracturing fluid properties. The role of polymers infracturing fluids is to provide fracture width, to suspend proppants, tohelp provide fracture width, to help control fluid loss to theformation, and to reduce friction pressure in the tubular goods. Guargum and cellulosic derivatives are the most common types of polymersused in fracturing fluids. The first patent on guar cross-linked byborate was issued on Oct. 16, 1962 (U.S. Pat. No. 3,058,909).Metal-based crosslinking agents developed by DuPont for plasticexplosive applications were found to be useful for manufacturingfracturing fluids for high temperature applications. Cellulosicderivatives are residue-free and thus help minimize fracturing fluiddamage to the formation and are widely used in Frac and Packapplications. The cellulosic derivatives are difficult to dispersebecause of their rapid rate of hydration. Guar gum and its derivativesare easily dispersed but produce some residue when broken.

An acid may be added to help dissolve minerals and initiate cracks inthe rock. Downhole, an acid reacts with minerals that are present in theformation to create salts, water, and carbon dioxide (i.e., isneutralized).

An acid/corrosion inhibitor may be added to protect well casing fromcorrosion. Downhole, it bonds to metal surfaces (i.e. pipe) downhole.Any remaining product not bonded is broken down by micro-organisms andconsumed or returned in produced water.

A biocide may be added to eliminate bacteria in the water that can causecorrosive byproducts. Downhole, the biocide reacts with micro-organismsthat may be present in the treatment fluid and formation. Thesemicro-organisms break down the product with a small amount of theproduct returning in produced water.

The Base Carrier Fluid (water) creates the fracture geometry andsuspends the proppant. Downhole, some of the Base Carrier Fluid stays inthe formation while the remainder returns with natural formation wateras “produced water” (actual amounts returned vary from well to well).

A “breaker” is an additive that allows a delayed break down of gels whenrequired. Downhole, the breaker reacts with the “crosslinker” and “gel”once in the formation making it easier for the fluid to flow to theborehole. The reaction produces ammonia and sulfate salts which arereturned in produced water.

Temporary or permanent clay stabilizers lock down clays in the shalestructure. Downhole, they react with clays in the formation through asodium-potassium ion exchange. This reaction produces sodium chloridewhich is returned in produced water. Clay stabilizers replace bindersalts like calcium chloride, helping to keep the formation intact as thecalcium chloride dissolves.

A crosslinker additive maintains the viscosity of the fracturing fluidas temperature increases. Downhole, it combines with the “breaker” inthe formation to create salts that are returned in produced water

A friction reducer is an additive that reduces friction effects (overbase water) in pipes. Downhole, it remains in the formation wheretemperature and exposure to the “breaker” allows it to be broken downand consumed by naturally occurring micro-organisms. A small amountreturns with produced water.

A gel additive may be used to thicken the water in order to suspend theproppant. Downhole, it combines with the “breaker” in the formation thusmaking it much easier for the fluid to flow to the borehole and returnin produced water.

Iron control additives are iron-chelating agents that help preventprecipitation of metal oxides. Downhole, they reacts with minerals inthe formation to create simple salts, carbon dioxide and water all ofwhich are returned in produced water.

A non-emulsifier may be added to break or separate oil/water mixtures(emulsions). Downhole, a non-emulsifier is generally returned withproduced water, but in some formations it may enter the gas stream andreturn in the produced natural gas.

A pH adjusting agent/buffer may be added to maintain the effectivenessof other additives such as cross-linkers. Downhole, it reacts withacidic agents in the treatment fluid to maintain a neutral (neitheracidic nor alkaline) pH. Reaction products are mineral salts, water andcarbon dioxide which are returned in produced water.

The propping agent (or “proppant”) is added to keep fractures openallowing for hydrocarbon production. Downhole, it preferably stays inthe formation, embedded in fractures (used to “prop” fractures open).

A scale inhibitor may be added to prevent scale in the pipe and theformation. Downhole, the product attaches to the formation. The majorityof product returns with produced water while the remaining portionreacts with microorganisms that break down and consume the product.

A surfactant may be added to reduce the surface tension of the treatmentfluid in the formation and thereby improve fluid recovery from the wellafter the fracturing operation is completed. Downhole, some surfactantsare designed to react with the formation, some are designed to bereturned with produced water or, in some formations, they may enter thegas stream and return in the produced natural gas.

Ammonium persulfate is often added to the fracturing fluids to break thepolymer as it reaches temperature. The first patent (U.S. Pat. No.3,163,219) on borate gel breakers was issued on Dec. 29, 1964.

Buffers are used in conjunction with polymers so that the optimal pH forpolymer hydration can be attained. When the optimal pH is reached, themaximal viscosity yield from the polymer is obtained. The most commonexample of fracturing fluid buffers is a weak-acid/weak-base blend,whose ratios can be adjusted so that the desired pH is reached. Some ofthese buffers dissolve slowly allowing the crosslinking reaction to bedelayed.

Gel stabilizers are added to polymer solutions to inhibit chemicaldegradation. Examples of gel stabilizers used in fracturing fluidsinclude methanol, tri-ethanol amine (TEA) and various inorganic sulfurcompounds. Other stabilizers are useful in inhibiting the chemicaldegradation process, but many interfere with the mechanism ofcrosslinking. The TEA and sulfur-containing stabilizers possess anadvantage over methanol, which is flammable, toxic, and expensive andmay cause poisoning of reactor tower catalysts.

Water Frac is composed of water, a clay control agent and a frictionreducer. Sometimes a water recovery agent (WRA) is added to reduce anyrelative permeability or water block effects. The advantages of using a“Water Frac” are the low cost, ease of mixing and the ability to recoverand reuse the water. The main disadvantage is the low viscosity whichresults in a narrow fracture width. Because the viscosity is low, themain proppant transport mechanism is velocity so water fracs aretypically pumped at very high rates (60 to 120 bpm). Fluid loss iscontrolled by the viscosity of the filtrate which is close to that ofwater—i.e. 1.

Linear Gel is composed of water, a clay control agent and a gellingagent such as Guar, HPG or HEC. Because these gelling agents aresusceptible to bacteria growth a bactericide or biostat is also added.Chemical breakers are also added to reduce damage to the proppant pack.WRA's are also sometimes used. The main advantage of a liner gel is itslow cost and improved viscosity characteristics. Fluid loss iscontrolled by a filter cake which builds on the fracture face as thefluid loses fluid to the formation. The main disadvantage is, as withwater fracs, the low viscosity which results in a narrow fracture width.The main disadvantage as compared to a water frac is that, because thereturned water has residual breaker, the water is not reusable.

Crosslinked Gels are composed of the same materials as a linear gel withthe addition of a crosslinker which increases the viscosity of thelinear gel from less than 50 cps into the 100's or 1000's of cps range.The higher viscosity increases the fracture width so it can accepthigher concentrations of proppant, reduces the fluid loss to improvefluid efficiency, improves proppant transport and reduces the frictionpressure. This crosslinking also increases the elasticity and proppanttransport capability of the fluid. Fluid loss is controlled by a filtercake which builds on the fracture face as the fluid loses fluid to theformation. A full description of the types of crosslinkers used, thechemistry and the mechanism of crosslinking is provided in the companionpaper on fracturing fluid components.

Oil Based Fluids are used on water-sensitive formations that mayexperience significant damage from contact with water based fluids. Thefirst fracturing fluid used to fracture a well employed gasoline as thebase fluid, palm oil as the gelling agent and naphthenic acid as thecrosslinker—i.e. napalm. Although some crude oils have particulateswhich could build a filter cake, fluid loss is generally considered tobe “Viscosity-Controlled—i.e. C-II”. There are some disadvantages inusing gelled oils. Gelling problems can occur when using high viscositycrude oils or crude oils which contain high levels of naturallyoccurring surfactants. When using refined oils such as diesel, the costis very high and the oil must be collected at the refinery before anyadditives such as pour point depressants, engine cleaning surfactants,etc. are added. Also, there are greater concerns regarding personnelsafety and environmental impact, as compared to most water-based fluids.

Foam/Poly Emulsions are fluids that are composed of a material that isnot miscible with water. This could be nitrogen, carbon dioxide or ahydrocarbon such as propane, diesel or condensate. These fluids are veryclean, have very good fluid loss control, provide excellent proppanttransport and break easily simply via gravity separation. Poly Emulsionsare formed by emulsifying a hydrocarbon such as condensate or dieselwith water such that the hydrocarbon is the external phase. Theviscosity is controlled by varying the hydrocarbon/water ratio. Foamsmade with nitrogen or carbon dioxide are generally 65 to 80% (termed 65to 80 quality) gas in a water carrying media which contains a surfactantbased foaming agent. Sometimes N₂ or CO₂ are added at a lowerconcentration (20 to 30 quality) to form “Energized Fluids”. This isdone to reduce the amount of water placed on the formation and toprovide additional energy to aid in load recover during the post-fracflow back period. Nitrogen can dissipate into the reservoir quitequickly, so fluids energized with N₂ should be flowed back as soon asthe fracture is closed. CO₂, under most conditions, is in a dense phaseat static, downhole conditions (prior to the well being placed inproduction), so is less susceptible to dissipation. CO₂ will dissolve incrude oil and thus may act to reduce the crude viscosity which, again,improves clean-up and rapid recovery. When N₂/CO₂ are added in qualitiesgreater than 80, the resulting mixture is termed a mist with a “0”viscosity. This quality is normally not used in fracturing. The maindisadvantage of these fluids is safety i.e. pumping a gas at highpressure or in the case of poly-emulsions and gelled propane, pumping aflammable fluid. CO₂ creates an additional hazard in that it can causedry ice plugs as pressure is reduced. These fluids are generally alsomore expensive and the gases may not be available in remote areas.

Characterization of Fracturing Fluids

Fluid viscosity for treatment design is determined from laboratory testsand is reported in service company literature. The ideal experiment fordescribing fluid flow in a fracture would be to shear a fluid betweentwo plates which are moving parallel and relative to one another. Suchan ideal test is not feasible for day-to-day applications so a rotating“cup and bob” viscometer know as a “Couette” viscometer is used. APIstandard RP39 and ISO 13503-1 fully describe the current testingprocedures used by the industry. The viscometer uses a rotating cup anda stationary bob with a gap between the two that simulates the fracture.

The tests described above measure the shear stress generated by specificincreasing shear rates (called a ramp), and this data is converted to a“viscosity” value by using a rheological model to describe fluidbehavior.

Another factor affecting viscosity is the addition of proppant to thefracturing fluid to from slurry. For a Newtonian fluid, the increase inviscosity due to proppant can be calculated from an equation originallydeveloped by Albert Einstein. For example, it can be shown that an 8-ppgslurry has an effective viscosity about 3 times that for the fracturingfluid alone. This increased viscosity will increase net treatingpressure and may significantly impact treatment design. This increase inslurry viscosity also retards proppant fall.

The rate of fall for proppant is normally calculated using Stokes' Law.Stokes' Law is generally not valid for Reynolds numbers much in excessof unity or for hindered settling due to proppant clustering in staticfluids. For cross-linked fluids the actual fall rate may be much lessthan Stokes' Law. Lab data shows that proppant in cross-linked fluidsfalls at a rate which is reduced by about 80% when compared tonon-cross-linked linear gels with the same apparent viscosity. The rateof proppant fall in foams and emulsions is also much less than would beindicated by using the apparent viscosity in Stokes' Law. Another factoraffecting proppant fall is the particle concentration which increasesslurry viscosity. This retards or hinders the proppant fall because ofclustered settling in static fluids. Finally the slurry flowing down afracture is generally much lower that the shear rate of 170 or 511 sec⁻¹used to report the fluid apparent viscosity.

When all of these factors are put together they can significantly affectthe viscosity. Treating pressure is fairly insensitive to viscosityinasmuch as the pressure is proportional to viscosity raised to the ¼power. However, the viscosity estimate can easily be off by an order ofmagnitude which can have a drastic impact on treatment behavior. Anorder of magnitude would be (10^(1/4)=1.8) so the treating pressurewould be 80% greater than anticipated. This could cause undesired heightgrowth and result in treatment failure. For fracturing jobs where thecontrol of net pressure to prevent height growth is important, fluidviscosity is a critical parameter.

What is needed is a fracturing system with the pumpability of a slickwater method and the proppant-carrying ability of a method employing across-linked gel. The present invention solves this problem.

BRIEF SUMMARY OF THE INVENTION

Disclosed hereinbelow is a method of hydraulic and natural fractureoptimization using a novel geomechanical and fluid design.

The present invention comprises not only a chemical component but rathera complete system and application that may encompass any type of viscousfluid ranging from natural polymers to synthetics. A system according tothe present invention comprises the targeted use of a low-viscosityfluid that is capable of carrying proppant ranging from silica white,resin coated, curable and ceramic proppants at concentrations rangingfrom 0.1 lb/gl-20 lbs/gl. In an exemplary embodiment, the actualviscosity of the demonstrated fluid encompasses 20 cP-150 cP at ambienttemperature at 511 1/s with R1:B1 bob configuration and equivalentviscosity with R1:B5 and R1:B2 configurations.

It has been found that, a viscosifying agent that comprises a copolymerpolymerized from an acrylic acid monomer and a monomer selected from:

-   -   a) about 20% to about 80% by weight of at least one carboxylic        acid monomer comprising acrylic acid, methacrylic acid, itaconic        acid, fumaric acid, crotonic acid, aconitic acid, or maleic        acid, or combinations thereof;    -   b) about 80% to about 15% by weight of at least one C₁ to C₅        alkyl ester and/or at least one C₁ to C₅ hydroxyalkyl ester of        acrylic acid or methacrylic acid;    -   c) about 0.01% to about 5% by weight of at least one        crosslinking monomer; and optionally    -   d) about 1% to about 35% by weight of at least one        α,β-ethylenically unsaturated monomer,    -   may be used to produce a fracturing fluid that has the        pumpability of a slick water fluid and the proppant-carrying        ability of a cross-linked gel.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWING(S)

The patent or application file contains at least one drawing executed incolor. Copies of this patent or patent application publication withcolor drawing(s) will be provided by the Office upon request and paymentof the necessary fee.

FIG. 1 is a schematic, cross-sectional view of a well undergoing atypical fracturing operation.

FIG. 2 is a flowchart depicting an integrated fluid-geomechanicsworkflow according to an embodiment of the invention.

FIG. 3A is a graph showing the viscosity of certain fluids versuspost-hydration time.

FIG. 3B is a graph showing proppant settling versus time for variousfracturing fluids.

FIG. 4 is a graph showing breaker profiles for various fracturing fluidsas viscosity versus time.

FIG. 5 is a graph showing hydration baselines for various additiveconcentrations as viscosity versus time.

FIG. 6A is the graphical output of a computer simulation of a fracturingoperation using a conventional high-viscosity fracturing fluid.

FIG. 6B is the graphical output of a computer simulation of a fracturingoperation using a conventional low-viscosity fracturing fluid.

FIG. 6C is the graphical output of a computer simulation of a fracturingoperation using a fracturing fluid according to an embodiment of theinvention.

FIG. 7A is the graphical output of a computer simulation of surfacetreating pressure calculations and related fracture dimensions for afracturing fluid according to the invention used at a level of 15 lbs.of the polymer per 1000 gallons of water (PPT).

FIG. 7B is the graphical output of a computer simulation of surfacetreating pressure calculations and related fracture dimensions for alinear gel fracturing fluid system that comprises natural guar or alow-residue hydroxypropyl guar (HPG) at a level of 40 lbs. per 1000gallons of water.

FIG. 7C is the graphical output of a computer simulation of surfacetreating pressure calculations and related fracture dimensions for aCHMPG/zirconium (carboxymethylhydroxypropyl guar gel) fracturing fluidsystem at a level of 40 lbs. per 1000 gallons of water.

FIG. 7D is the graphical output of a computer simulation of surfacetreating pressure calculations and related fracture dimensions for adelayed borate crosslinked fracturing fluid system at a level of 40 lbs.per 1000 gallons of water.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 illustrates a treatment system 20 according to one embodiment ofthe present invention for treating a formation intersected by a wellbore10. A tubing string 12 deploys from a rig 30 into the wellbore 10. Thestring 12 has fracture sleeves 100A-C disposed along its length. Variouspackers 40 may isolate portions of the wellbore 10 into isolated zones.In general, the wellbore 10 can be an opened or cased hole, and thepackers 40 may be any suitable type of packer intended to isolateportions of the wellbore into isolated zones.

The fracture sleeves 100A-C on the tubing string 12 between the packers40 are initially closed during run in, but may be opened to diverttreatment fluid to the isolated zones of the surrounding formation, asdiscussed below. The tubing string 12 may be part of a fractureassembly, for example, having a top liner packer (not shown), a wellboreisolation valve (not shown), and other packers and sleeves (not shown)in addition to those shown. If the wellbore 10 has casing, then wellbore10 may have casing perforations 14 at various points.

As conventionally done, operators deploy a setting ball to close thewellbore isolation valve (not shown). Then, operators rig up thefracturing surface equipment at the rig 30 and pumping system 35 andpump fluid down the wellbore 10 to open a pressure-actuated sleeve (notshown) toward the end of the tubing string 12. This treats a first zoneof the formation.

Then, in later stages of the operation, operators selectively actuatethe fracture sleeves 100A-C between the packers 40 to treat the isolatedzones depicted in FIG. 1. A number of mechanisms and techniques may beused to open the fracture sleeves 100A-C. In a typical arrangement,successively dropped plugs or balls engage a respective seat in each ofthe fracture sleeves 100A-C and create a barrier to the zones below.Applied differential tubing pressure may then be used to shift therespective sleeve 100A-C open so that the treatment fluid may stimulatethe adjacent zone. Some ball-actuated fracture sleeves may bemechanically shifted back into the closed position. This affords theoperator the ability to isolate problematic sections where water influxor other unwanted egress from the formation or a previously fracturedzone may take place.

In treating the zones of the wellbore 10, fracture equipment of the rig30 and pump system 35 at surface pump the treatment fluid (e.g., carrierfluid, fracture proppant, etc.) down the tubing string 12. In general,the rig 30 may have a fluid system, a launcher, and a pressure controlassembly (i.e., blowout preventer, wellhead, shutoff valve, etc.). Thelauncher may be used to launch the plugs, such as darts, fracture balls,or other actuating devices, for opening downhole fracture sleeves 100A-Cdisposed on the tubing string 12. For its part, the pump system 35includes one or more flow lines, pumps, control valves, a fluidreservoir (e.g., pit or tank), a solids separator, various sensors,stroke counters, and a proppant mixer.

The industry is in need of a low-viscosity fracturing fluid option.Increasingly, operators request a high-viscosity friction reducer thatoffers better carrying capacity than traditional friction reducers.Although production may be gained by this approach, the models predict amajor loss of proppant placement when using conventional fluids.

As discussed in detail above, hydraulic fracturing is widely utilized toimprove hydrocarbon productivity from permeability challengedreservoirs. During a typical hydraulic fracturing treatment, afracturing fluid is injected into a wellbore and penetrated into a rockformation at a pressure above the formation pressure so as to createtensile open area. Following the first initiation phase, proppant isadded to the fracturing fluid and injected into the newly created openarea to prevent it from closing during production and also to provideconductive flow paths for hydrocarbon extraction from the target area.The overall success of the fracturing treatment and induced fracturecharacteristics (such as length, height, extent, and conductivity) aredependent on the rheological properties of the fracturing fluid whichalso influences proppant transport, distribution and mechanical behaviorwithin the developed hydraulic fracture and/or reactivated naturalfractures.

Currently, high concentrations and/or high-strength proppants aretypically used in the industry to minimize proppant embedment and crushand hence the fracture closure risk. However, in order to utilize highproppant concentrations and/or high-strength proppants, the rheologicalproperties of the fracturing fluid must be carefully chosen in order toget the proppant to where it is most needed in the reservoir so as tomaximize long-term production. When a low-viscosity fluid (such as slickwater) is selected, the hydraulic fracture could be initiated,propagated and well-contained within the pay zone, however, highconcentration and/or high-strength proppant tends to settle andaccumulate on the bottom of the developed fractures which may greatlydiminish the treatment efficiency. Thus, to carry a high concentrationand/or high-strength proppant and provide relatively uniformdistribution throughout the complex fracture network, one must use ahigh-viscosity fluid. Using a high-viscosity fluid may mitigate theproppant settling issue; however, it may also lead to: higher requiredpumping horsepower; lower propped fracture length with abnormallygreater fracture height; lower conductive reservoir volume with lessnatural fracture reactivation; and, greater formation damage andresidual guar polymer during flow back. Using a high-viscosity fluid,hydraulic fracture can readily extend out of the target zone and resultin un-constrained fracture height growth. A massive portion offracturing fluid and proppant could be sent into non-target zones andgreatly decrease the treatment efficiency.

In order to overcome these obvious shortcomings, the present inventionprovides a fluid design with optimal rheological properties thatreplicates slick water flowback while providing the highproppant-carrying capacity that is commonly observed inhigh-concentration crosslinked systems; i.e., highly viscous fluids. Byutilizing such a fluid, proppant delivery into the natural fracturenetworks may be achieved without unacceptably high pumping horsepowerwhich is often encountered when running conventional highly viscousfluids. In summary, in order to maximize the stimulation efficiency of areservoir, there is a need for a fluid and a methodology that providesthe ability to transport high concentration and/or high-strengthproppant without having to rely on the traditional approach which usesviscosity alone as a guide for selection.

Furthermore, the fluid design and proppant selection strategy should becustomized and evaluated based on the local geological and formationcharacteristics. If engineered accurately, a fit-for-purpose fluid maywell distribute the selected proppant into the fracture surface, whichmay sustain closure stresses by reducing embedment and/or crush risk,and result in longer effective fracture length(s) and larger conductivereservoir volume with enhanced conductivity and hence production. Thus,there is a need for an integrated geo-mechanics-fluid workflow that iscapable of providing an optimized design and/or evaluating and improvingexisting designs based on the reservoir properties and instrumentlimitations by iteratively optimizing relevant aspects/controls (such asfluid design, proppant type, pumping schedule) of a fracturingoperation.

In the past, high-viscosity fluid (greater than 800 centipoise) has beenthe preferred solution for increased proppant transport and reducedproppant settling. This methodology has been effective using systemssuch as a borate-crosslinked fluid with a polymer loading of 40 lbs. per1000 gallons of water and offers what the industry considers a standardfor low-rate pumping with high proppant transporting, 40 BPM and >5 ppg,respectively. The downside of high polymer loads of guar is that theycommonly increase formation damage created in the fracturing process,typically resulting in an 86% percent regain permeability value. Whilethis may be acceptable, additional loss of needed fracture length iscommonly observed when high-viscosity fluids are utilized to carryproppant. However, greater fracture geometry width is often considered acommon characteristic of high viscosity fluids. Often, withlow-viscosity fluids such as linear gels and friction reducers, fracturelength may be established allowing breaks into the secondary fractureand mechanical reactivation of the pre-existing natural fracture networkmay be enhanced due to the interaction between natural fractures andpropagating hydraulic fractures. Each individual natural fracture withinthe fracture network can reactivate in opening, slip or a combined modewith greatly increased fracture conductivity, which allows thefracturing fluid together with proppant to be diverted from thepropagating hydraulic fractures into the fracture network. However,these fluids do not offer suspending characteristics past 30 minutesunder static conditions. When applied to fracture geometry, this loss ofsuspending ability causes proppant to fall from suspension resulting inloss of uniform proppant placement and induce early closure at thelocation with less proppant coverage. As for the complex fracturegeometry, the loss of suspending ability may also cause blockage at theintersection between the reactivated natural fractures and hydraulicfractures, introduce additional pressure loss, and consequently reducethe proppant transport efficiency and form potential chock points withthe fracture network. In instances where frac gradients are high,high-viscosity fluids are often used to allow for lower treating rates.This approach is often taken with high viscosity fluids, but addedtreatment pressure may be required on surface, resulting in additionalpumping horsepower requirements.

A secondary approach (and a more recent industry option) is the use of ahigh-viscosity friction reducer. As compared to guar-based systems, theviscosity of such fluids is far lower. However, proppant transport insuch systems is not comparable to either alterative fluid systems orborate-crosslinked systems. When attempting to replicate the suspendingproperties of alternative fluid systems or borate cross-linked systemswith a friction reducer, the friction reducer must be employed at aconcentration that is not economically feasible and fluid compatibility(in terms of polymer actually working) suffers.

There is no existing, integrated, geo-mechanics-fluid workflow that canguide and optimize the fluid design for proppant transport duringfracturing operations as described below.

The trend in the industry has been to obtain a high suspendingcharacteristic fluid [as defined above] by increasing the fluidviscosity to more than 500 cP. Although this may be effective, fracturegeometry may be adversely affected to a great extent. In contrast, thecharacteristics of a fluid according to the present invention are thatof a low-viscosity system (similar to those of a linear fluid) but withsuspending behavior better than even twice the weight of active polymer.Significantly, the fluid of the present invention exhibits suspendingbehavior greater than that of a 1000-cP system yet has an actualviscosity less than 100 cP. Reservoir concept models indicate that thefluid of the present invention may actually suspend and carry theproppant within the main hydraulic fractures as well as place proppantinto reactivated natural fractures. An additional advantage of the newfluid system that is particularly needed is that the low-viscositybehavior may actually minimize the pumping horsepower requirement andimprove the proppant coverage when carrying large/heavy proppant,keeping the proppant in the desired place, enhancing the conductivity ofthe stimulated fracture and reactivating natural fractures. With alow-viscosity fluid, the pumping horsepower required on location duringa fracturing operation is lower. The high-viscosity fluids of the priorart require additional pumping horsepower on location to combat theadded frictional pressure loss of high viscosity fluids such ascrosslinked fluids where a viscosity no less than 200 cP may be reachedon surface. This, along with other cross-linked fluids, may causetreatment rates to be reduced to compensate for the higher treatmentpressure (especially when frac gradients are high). Low-viscosity fluidssuch as the new fluid of the present invention provide low viscosity yetmore effective proppant transporting thereby keeping the proppant moreeffectively suspended and reducing perf bridging and proppant settlingbetter than crosslinked fluids.

Low-viscosity fluids such as high-concentration friction reducers andlinear gelling agents like guar are common, but do not allow proppant tobe placed as effectively in fractures as the fluid of the presentinvention does. In terms of injection pressure, the fluid of the presentinvention is consistent with a conventional low-viscosity fluid such asa friction reducer. However, it has more than double theproppant-suspending power, which mitigates proppant settling within thefracture geometry, especially within a complex fracture network.

FIG. 3A illustrates the apparent viscosity of a fluid according to theinvention in reference to the API 39 statement and provides a viscositycomparison of borate/guar fluid and a fluid according to the invention.It shows the viscosity versus time of DynaFrac which is a 40-lb.borate/guar system at 163° F. and that of a fluid according to theinvention is shown at both room temp and at 163° F. FIG. 3A whenreferenced to FIG. 3B illustrates that, merely because a fluid yieldshigh viscosity, proppant settling is not necessarily improved over alow-viscosity fluid.

In addition, it will be appreciated that, because of the low viscosityof a fluid according to the invention (as compared to a borate/guarsystem), less horsepower on surface is needed due to pumping fluiddynamics of viscosity principle.

FIG. 4 shows that the new fluid of the present invention is not affectedin terms of viscosity at surface temperature when breaker is introduced.Often, in guar systems and true slickwater, breaking behavior begins tooccur even at surface temperature. A system according to the presentinvention is preferably broken with ammonium persulfate breaker.

FIG. 5 illustrates making active co-polymer into a slurry form foreasier field deployment and pumpability. Due to the surfactant and claycomponents used when making a slurry, the active co-polymer dispersesmore effectively into solution. This is illustrated where a 15-lb.slurry system yields a more effective viscosity than when a 20-lb dryform a/k/a co-polymer used alone. [don't see “15” in FIG. 5]

Referring now to FIGS. 6A-6C, computer simulation results of fracturingoperations using a conventional high viscosity fluid (aborate-crosslinked guar-based system), a conventional low-viscosityfluid (slickwater), and the new fluid of the present invention areshown, respectively. In FIGS. 6A-6C, “NF” denotes natural fractures and“HF” denotes hydraulic fractures. Proppant dispersion is shown as a“heat map” wherein red areas have a high proppant concentration and blueareas have a low proppant concentration. Green and yellow areas haveintermediate proppant concentrations. The ideal solution is alow-viscosity fluid which has high proppant carrying capacity whilerequiring relatively low power for injection.

The simulation results presented in FIGS. 6A-6C are based on the use ofa 3-D reservoir scale fracturing simulator to model hydraulic fracturepropagation, natural fracture reactivation and proppant transport withinboth hydraulic fracture and reactivated natural fracture networks.

State-of-the-art numerical simulations for fracturing are based oncoupled Fracture Mechanics (FM) and Fluid Dynamics (FD). FM is a branchof solid mechanics that uses algorithms as well as numerical analysis toanalyze (or solve) fracture propagation inquiries or problems. FMapplies the theories of elasticity and plasticity to predict the rockfailure behavior with respect to intrinsic mechanical properties andboundary conditions. FD is a sub discipline of fluid mechanics that maybe used for simulating interactions involving fracturing fluid flow,fracture surfaces, proppant transport and boundary conditions.Fracturing fluid and proppant flow within a complex fracture network andthe induced stress generated by fracture propagation and deformation arefully coupled in the 3-D reservoir scale fracturing simulator. CoupledFM and FD analysis may be used to understand and evaluate the influenceof the proppant-carrying capacity of fluid and pumping strategy on theproppant transport efficiency in a complex fracture network. Forexample, coupled FM and FD may be used in some embodiments foroptimizing the parameters affecting the proppant distribution within adeveloped fracture network such as, for example, injection rate,injection duration, proppant type and proppant concentration in thefluid.

To evaluate and quantify the efficiency of a proppant transport processusing the new fluid of the present invention, an integratedgeo-mechanics workflow comprised of multiple modules may be used, asshown in FIG. 2. In general, this workflow combines quick-look analysis(i.e. candidate selection) with advanced computational models (i.e.CFD-DEM [computational fluid dynamics—discrete element method] andgeo-mechanical models) to provide operational guidelines to improveproppant deliverability and maximize production. Multiple analytical andnumerical models and/or modules may be combined within the framework ofthe workflow to assess the design efficiency and customized fluidproperties of the present invention.

Certain embodiments of the invention iteratively employ analytical andnumerical functions and modeling, for example to run simulations andobtain the results thereof. In particular, as discussed in furtherdetail below, specifically directed use of coupled Computational FluidDynamics (CFD), Discrete Element Methods (DEM), and analytical modelsmay be used to create custom design and verify the experimental resultson new fluid proppant carrying capacity characteristics.

Using logs and real-time log files obtained from an actual well inArgentina, simulations of pumping rate, frac geometry, and hydraulichorsepower (HHP) requirements were performed. In each case, the newfluid according to the present invention was shown to require less HHPthan other representative fracturing fluids.

TABLE 1 presents simulation data using a pumping rate of 40 BPM as abaseline to provide an idea of HHP requirements at a low rate. It willbe appreciated by those skilled in the art that a pumping rate of 40 BPMis not realistic for the proppant (at 5 PPG) used in actual slickwater(friction reducer) field applications. However, the new fluid is stillshown to be more efficient in terms of lower hydraulic horsepowerrequired and greater propped fracture coverage.

TABLE 1 Rate Avg. Frac Total fract Total prop. Perf Fluid PPG BPM PSILength (ft.) prpL height Ht. W HHP Guar 1-5 40 11,170 118.7 92.7 253.8198.3 .304 10,950 Slickwater 1-5 40 9978 147.6 77.3 253.0 196.0 .2629782 Borate/Guar 1-5 40 10,850 121.0 92.5 245.9 188.0 .336 10,637 Newfluid 1-5 40 9550 121.7 114.4 253.1 186.4 .312 9363

The simulations presented in TABLE 2 applied what would be the minimalpumping rate required to successfully pump a well without screening outand/or bridging off perforations. This is more so focused when lineargelled fluids and or slickwater fluids are applied (both were consideredin determining pumping rate, with an error factor of 10%).

TABLE 2 Rate Avg. Frac Total Frac Total prop. Perf Fluid PPG BPM PSILength (ft.) prpL height Ht. W HHP Guar 1-5 60 12,982 125.1 92.9 267.1198.3 .418 19,091 Slickwater 1-5 90 12,444 127.2 93.2 275.0 201.5 .46627,449 Borate/Guar 1-5 55 12,267 121.4 90.3 255.0 190.0 .650 16,536 Newfluid 1-5 45 10,529 123.0 118.5 258.4 198.0 .314 11,613

The simulations presented in TABLE 3 utilized the actual pump schedulethat would likely be used with the new fluid. Inasmuch as the job beingmodeled required a low rate and high proppant amounts to pump proppantaway, slickwater was not considered. At 5 ppg, proppant is fallingquicker than fluid at 60 BPM. Use of the new fluid according to thepresent invention is shown to reduce required HHP by the equivalent oftwo trucks having skid-mounted pumps and the equivalent of four truckshaving body-loaded pumps.

TABLE 3 Rate Avg. Fracture Total frac Total prop. Perf Fluid PPG BPM PSILength (ft.) prpL height height width HHP Guar 1-5 60 12,907 180.4 161.8295.6 265.3 0.728 18,980 MF 40 1-5 60 13,317 151.1 137.4 310.7 282.60.895 19,584 DF 40 1-5 60 12,790 162.3 146.5 310.7 280.6 0.798 18,808New fluid 1-5 60 10,853 184.2 161.6 294.0 257.9 0.720 15,960

In the above tables, the following abbreviations are used:

-   -   prpL=propped Frac Length (in feet)    -   ttl Frac Ht=Total Frac Height (in feet)    -   ttl prpHt=Total Propped Frac Height (in feet)    -   Perf W=Perforation width (in feet)    -   HHP=Hydraulic Horsepower    -   DF=DynaFrac® delayed borate crosslinked fluid and additives        [WEATHERFORD TECHNOLOGY HOLDINGS, LLC 2000, ST. JAMES PL.,        HOUSTON, Tex. 77056] (GuarHPG/borate crosslink)    -   MF=a CMHPG/zirconium crosslinked fluid    -   Guar=Standard linear fluid, e.g. AquaVis® water-soluble polymers        [HERCULES LLC, 500 HERCULES ROAD, WILMINGTON, Del. 19808]

FIGS. 7A-7D are graphical representations from simulations of surfacepressure, net pressure, wellbore friction, fracture length, fractureupper height, fracture lower height, and the maximum width of fractureat wellbore versus time for various convention fracturing fluids and thenew fluid of the present invention.

Current numerical simulations for particle settling analysis are basedon coupled Computational Fluid Dynamics (CFD) and Discrete ElementMethods (DEMs). CFD is a branch of fluid mechanics using algorithms aswell as numerical analysis to analyze (or solve) fluid flow inquiries orproblems. CFD is a computer-based mechanism for making calculations tosimulate interactions involving liquids, gases, surfaces, and boundaryconditions. DEM belongs to a well-known family of numerical methods usedto compute particle motion and interaction. These models may be used tobetter design and calibrate against particle settling experiments. Inmany embodiments, coupled CFD and DEM analysis may be used to understandand evaluate the proppant carrying capacity of a certain fluid. Forexample, coupled CFD and DEMs may be used in some embodiments foroptimizing the parameters affecting proppant settling properties suchas, for example, proppant size, proppant density, and proppantconcentration (in the fluid). However, it should be appreciated that themethod may be generalized to any proppant and any fluid to optimize theparameters that affect proppant settling.

The workflow may start with a candidate ranking and selection module toensure that correct wells and/or stages are ranked and chosen forhydraulic fracturing. This module may contain input data collection andquick-look analysis to compare and contrast fracture potential betweenmultiple well(s) or well stage(s). The input data may be collected frommultiple sources, including core samples, log data and field data. Thecollected data and/or attributes may include reservoir characteristics(e.g., depth, pore pressure gradient, porosity, permeability, TOC, watersaturation) and the geo-mechanical properties of the play (e.g., Young'smodulus, Poisson's ratio, rock strength, cohesion and shmin gradient(minimum horizontal in-situ stress)), which may be ranked and integratedto predict the fracture potential.

Once the most viable candidate wells and/or stages are chosen,experiments and/or numerical analysis may be conducted to quantify andassess the proppant-carrying capacity of the fracturing fluid of thepresent invention using the fluid and proppant design module. Theavailable experimental and/or field test results may also be utilized tocalibrate the numerical small-scale engine (e.g., CFD & DEM) for anyfuture analysis, which may result in cost savings. With the aid of thenumerical model, or by actual experiments and/or field tests, the fluidproperties (viscosity, density, and proppant carrying capacity),proppant type and concentration may be modified and/or re-designed inorder to achieve higher proppant carrying capacity, lower proppantsettling, and appropriate stability of the fluid based on the specificreservoir and injection conditions. This process may be repeated untilan optimized fluid and proppant design is obtained, which may be furtheranalyzed in the fracture design module using an advanced geo-mechanicaland production model.

The fracture design module may first simulate proppant transport usingthe fluid and proppant properties exported from the previous analysisand may quantify proppant coverage and distribution using an advancedgeo-mechanical model. The geo-mechanical analysis may model hydraulicfracture propagation, fracture height growth, natural fracturereactivation, and proppant transport within both hydraulic fractures andreactivated natural fracture networks. The geo-mechanical model may alsosimulate proppant mechanical deformation (both embedment and crush) andthe resulting fracture closure behavior during production to quantifyconductivity reservoir volume for production analysis. The relevantmechanical properties and behavior of the chosen proppant type arepreferably calibrated through related experimental work and implementedinto the numerical models.

The workflow may include production prediction to evaluate any proposedor existing design for a specific formation. If the predicted productionfalls below the target value or an economically viable level, theanalysis module may adjust the engineering design parameters and/orcontrols such as fluid property, proppant type, injection rate, pumpingschedule, etc. (which, in an embodiment, includes an emphasis on theproppant-carrying properties of the fluid of the present invention) anditeratively rerun the fluid and proppant design module and the fracturedesign module until obtaining an improved and/or optimized design. Oncean acceptably optimized engineering design is obtained, the analysismodule may output design parameters for use in customizing the fluidproperties of the present invention and to guide the field operations soas to maximize production.

A fluid according to the present invention allows proppant to be placedinto fractures more efficiently than conventional fracturing withlow-viscosity properties. This provides higher proppant carryingcapacity within the fracture system (main hydraulic fracture andactivated natural fractures). In addition, it minimizes the pumpinghorsepower requirement by minimizing the fluid viscosity. Moreover,lower fluid viscosity results in less wellbore damage and reducedresidual polymer within the formation by increasing the regainpermeability (e.g., increasing to 96.5 md from 85 md when comparedequally at a 20-lb. concentration). The fluid system of the presentinvention does not depend upon inherent viscosity to suspend andtransport proppant. A fluid that utilizes a three-dimensionalproppant-suspending mechanism in a relatively low-viscosity environmentmay be made using polyacrylamide polymers that are functionalized viasynthesis using a free-radical micellar polymerization method with lowamounts of anionic long-chain alkyl, sodium 9- (and 10-)acrylamidostearate with AMPS, sodium dodecyl sulfate, vinyl pyrrolidone,hydroxyethyl acrylate and/or ionizable carboxylic groups depending uponthe desired final fluid rheological properties and brinecompatibilities. For some versions of the fluid, minor amounts of othermono-functional or poly-functional monomers including styrene, vinyltoluene, butyl acrylate, methyl methacrylate, vinylidene chloride, vinylacetate and the like may also be added to the backbone of the mainpolymer once the water solubility of the polymer is assured.

In addition, the fluid system of the present invention may be optimizedusing an integrated geo-mechanical-fluid flow workflow. Multiple scalesof both analytical and numerical models may be set up and utilized inthe workflow to assess the proppant carrying capacity of the fluid ofthe present invention and ensure the success of utilizing the fluid ofthe present invention. The fluid of the present invention designmethodology may be customized and flexible based on availableexperimental data, reservoir condition, proppant type and user-specificrequirements to enhance the proppant carrying capacity while loweringthe required pumping horsepower for injection. The fluid design may becoupled with reservoir-scale fracture simulations. By comparing andcontrasting different design plans, the proppant settling, embedment andcrush may be minimized so as to enhance the proppant coverage andconductive reservoir volume within the framework of the workflow. Insuch a way, the engineering parameters, including fluid properties,proppant type and pumping schedule, may be iteratively optimized toenhance the proppant-carrying efficiency of the fluid of the presentinvention and hence the overall production. The ultimate decision on thefluid design strategy for a successful hydraulic fracture treatmentshould be assessed within the local geological condition by using theintegrated workflow for thorough evaluation. Thus, the engineering fluiddesign and pumping schedule may be customized based on data unique todifferent formations.

An exemplary viscosifying agent according to one embodiment of theinvention is product that comprises a copolymer that has beenpolymerized using two separate monomers—the first being an acrylic acidmonomer and the second comprising a monomer selected from;

-   -   a) about 20% to about 80% by weight of at least one carboxylic        acid monomer comprising acrylic acid, methacrylic acid, itaconic        acid, fumaric acid, crotonic acid, aconitic acid, or maleic        acid, or combinations thereof;    -   b) about 80% to about 15% by weight of at least one C₁ to C₅        alkyl ester and/or at least one C₁ to C₅ hydroxyalkyl ester of        acrylic acid or methacrylic acid;    -   c) about 0.01% to about 5% by weight of at least one        crosslinking monomer; and optionally    -   d) about 1% to about 35% by weight of at least one        α,β-ethylenically unsaturated monomer selected from;

CH₂═C(R)C(O)OR¹

-   -   wherein R is selected from hydrogen or methyl; and R¹ is        selected from C₆-C₁₀ alkyl, C₆ to C₁₀ hydroxyalkyl,        —(CH₂)₂OCH₂CH₃, and —(CH₂)₂C(O)OH and salts thereof.

CH₂═C(R)X

-   -   wherein R is hydrogen or methyl; and X is selected from —C₆H₅,        —CN, —C(O)NH₂, —NC₄H₆O, —C(O)NHC (CH₃)₃, —C(O)N(CH₃)₂,        —C(O)NHC(CH₃MCH₂)₄CH₃, and —C(O)NHC(CH₃)₂CH₂S(O)(O)OH and salts        thereof.

CH₂═CHOC(O)R¹

-   -   wherein R¹ is linear or branched C₁-C₁₈ alkyl; and

CH₂═C(R)C(O)OAOR²

-   -   wherein A is a divalent radical selected from —CH₂CH(OH)CH₂—,        and —CH₂CH(CH₂OH)—, R is selected from hydrogen or methyl, and        R² is an acyl residue of a linear or branched, saturated or        unsaturated C₁₀ to C₂₂ fatty acid.

The polymerization may be a random polymerization—i.e., although on aweight basis there is a certain, selected amount of each monomer, theorder in which the monomers are arranged in the polymer backbone is notdefinite.

In the copolymer, the predominant monomer in the polymer is preferablyacrylic acid, with relatively little of the secondary monomer in thepolymer. The overall MW of the copolymer may be very high, approximately1,000,000,000 Daltons.

Of course many variations may be substituted to obtain a similar effectby those skilled in the art.

The foregoing presents particular embodiments of a system embodying theprinciples of the invention. Those skilled in the art will be able todevise alternatives and variations which, even if not explicitlydisclosed herein, embody those principles and are thus within the scopeof the invention. Although particular embodiments of the presentinvention have been shown and described, they are not intended to limitwhat this patent covers. One skilled in the art will understand thatvarious changes and modifications may be made without departing from thescope of the present invention as literally and equivalently covered bythe following claims.

1. A viscosifying agent for a hydraulic fracturing fluid comprising: acopolymer polymerized using two different monomers wherein the firstmonomer is an acrylic acid monomer and the second monomer is selectedfrom the group consisting of a) a carboxylic acid monomer, b) a C₁ to C₅alkyl ester and/or a C₁ to C₅ hydroxyalkyl ester of acrylic acid ormethacrylic acid, and c) a crosslinking monomer.
 2. The viscosifyingagent recited in claim 1 further comprising at least oneα,β-ethylenically unsaturated monomer selected from the group consistingof:CH₂═C(R)C(O)OR¹ where R is selected from hydrogen or methyl and R¹ isselected from C₆-C₁₀ alkyl, C₆ to C₁₀ hydroxyalkyl, —(CH₂)₂OCH₂CH₃, and—(CH₂)₂C(O)OH and salts thereof.CH₂═C(R)X where R is hydrogen or methyl; and X is selected from —C₆H₅,—CN, —C(O)NH₂, —NC₄H₆O, —C(O)NHC (CH₃)₃, —C(O)N(CH₃)₂,—C(O)NHC(CH₃MCH₂)₄CH₃, and —C(O)NHC(CH₃)₂CH₂S(O)(O)OH and salts thereof.CH₂═CHOC(O)R¹ where R¹ is a linear or branched C₁-C₁₈ alkyl; andCH₂═C(R)C(O)OAOR² where A is a divalent radical selected from—CH₂CH(OH)CH₂—, and —CH₂CH(CH₂OH)—, R is selected from hydrogen ormethyl, and R² is an acyl residue of a linear or branched, saturated orunsaturated C₁₀ to C₂₂ fatty acid.
 3. The viscosifying agent recited inclaim 2 wherein the at least one α,β-ethylenically unsaturated monomercomprises about 1% to about 35% by weight of the copolymer.
 4. Theviscosifying agent recited in claim 1 wherein the carboxylic acidmonomer is selected from the group consisting of acrylic acid,methacrylic acid, itaconic acid, fumaric acid, crotonic acid, aconiticacid, maleic acid, and combinations thereof.
 5. The viscosifying agentrecited in claim 1 wherein the carboxylic acid monomer comprises about20% to about 80% by weight of the copolymer.
 6. The viscosifying agentrecited in claim 1 wherein the C₁ to C₅ alkyl ester and/or a C₁ to C₅hydroxyalkyl ester of acrylic acid or methacrylic acid comprises about80% to about 15% by weight of the copolymer.
 7. The viscosifying agentrecited in claim 1 wherein the C₁ to C₅ alkyl ester is a C₁ to C₅hydroxyalkyl ester of acrylic acid.
 8. The viscosifying agent recited inclaim 1 wherein the C₁ to C₅ alkyl ester is a C₁ to C₅ hydroxyalkylester of methacrylic acid.
 9. The viscosifying agent recited in claim 1wherein the crosslinking monomer comprises about 0.01% to about 5% byweight of the copolymer.
 10. The viscosifying agent recited in claim 1wherein the copolymer is a random copolymer.
 11. The viscosifying agentrecited in claim 1 wherein acrylic acid is the predominant monomer inthe copolymer.
 12. The viscosifying agent recited in claim 1 wherein themolecular weight of the copolymer is about 1×10⁹ Daltons.
 13. Theviscosifying agent recited in claim 1 wherein the molecular weight ofthe copolymer is at least 1×10⁹ Daltons.
 14. The viscosifying agentrecited in claim 1 wherein the molecular weight of the copolymer isgreater than 1×10⁹ Daltons.
 15. A method of hydraulically fracturing asubterranean formation comprising: suspending a proppant in a fluidcomprising a viscosifying agent comprising a copolymer polymerized usingtwo different monomers wherein the first monomer is an acrylic acidmonomer and the second monomer is selected from the group consisting ofa) a carboxylic acid monomer, b) a C₁ to C₅ alkyl ester and/or a C₁ toC₅ hydroxyalkyl ester of acrylic acid or methacrylic acid, and c) acrosslinking monomer; and injecting the fluid comprising theviscosifying agent and suspended proppant into the formation.
 16. Themethod recited in claim 15 further comprising: injecting a breaker intothe formation; and recovering at least a portion of the fracturing fluidby flow back.
 17. The method recited in claim 16 wherein the breaker isan oxidative breaker.
 18. The method recited in claim 17 wherein thebreaker is selected from the group consisting of ammonium persulfate andperoxide breakers.
 19. A method for hydraulically fracturing ahydrocarbon-producing subterranean formation comprising: rankingcandidate wells or well sections for hydraulic fracturing; performingnumerical analysis to quantify and assess the proppant-carrying capacityof a selected fracturing fluid; selecting the fracturing parameters; anddelivering the fracturing fluid to the formation at the selectedfracturing parameters.
 20. The method recited in claim 19 whereinselecting the fracturing parameters comprises selecting a fracturingfluid, a proppant type, a proppant concentration, and a pumping rate.21. The method recited in claim 19 wherein ranking candidate wells orwell sections comprises a consideration of one or more factors selectedfrom the group consisting of reservoir depth, pore pressure gradient,porosity, permeability, TOC, water saturation, Young's modulus,Poisson's ratio, rock strength, cohesion and shmin gradient.
 22. Themethod recited in claim 19 further comprising performing numericalanalysis to quantify the proppant-carrying capacity of the fracturingfluid.
 23. The method recited in claim 19 further comprising performingnumerical analysis to quantify the proppant-carrying capacity of thefracturing fluid with respect to fluid viscosity and density.
 24. Themethod recited in claim 19 further comprising performing numericalanalysis to quantify the proppant-carrying capacity of the fracturingfluid with various proppant types and concentrations.
 25. The methodrecited in claim 19 wherein selecting the fracturing parameters,comprises: performing a simulation to predict the hydraulic fracturepropagation, fracture height growth and natural fracture reactivation;performing a simulation to model the proppant transport within both mainhydraulic fractures and a reactivated natural fracture network;performing a simulation to assess the proppant embedment and crush andfracture surface closure behavior during production; performing asimulation to forecast the production efficiency; and choosing a beststimulation design by a comparison of the predicted result correspondingto a typical design plan, wherein fracturing parameters of the plannedstimulation operations are optimized based upon the extent of conductivereservoir volume and production efficiency.
 26. The method recited inclaim 25, wherein the fracturing parameters include a modified pumpingschedule.
 27. The method recited in claim 26, wherein the modifiedpumping schedule includes changing an injection time, rate, proppanttype and fluid properties.
 28. The method recited in claim 27, whereinthe fluid properties includes viscosity and density affecting theproppant transport process.
 29. The method recited in claim 27, whereinthe change of fluid properties and its impact on the proppant carryingcapacity is quantified or estimated by numerical analysis.
 30. Themethod recited in claim 19 wherein selecting the fracturing parametersis performed with respect to a certain geological condition using anintegrated fluid-geomechanics workflow.